Coterra Energy Inc (CTRA) 2016 Q4 法說會逐字稿

Good morning, and welcome to the Cabot Oil & Gas Corporation's 2016 year end and fourth quarter earnings conference call.

(Operator Instructions)

Please note that this event is being recorded. I would now like to turn the conference over to Dan Dinges, Chairman, CEO and President. Please go ahead.

Thank you, Anita, and good morning, all. Thank you for joining us today for Cabot's fourth quarter and full-year 2016 earnings call. With me today, I do have the member of Cabot's -- members of the Cabot's executive team.

On today's call, I will be referring to slides from the earnings presentation we posted to our website this morning, which highlight our operational and financial results for 2016, as well as our plans for 2017. Before we get started, I would like to move to slide 2 of the presentation which addresses [about] forward-looking statements.

Please note that we will make forward-looking statements based on current expectations this morning. Also some of our comments may reference non-GAAP financial measures, forward-looking statements, and other disclaimers. As well as reconciliations to the most directly comparable GAAP financial measures are provided in both the earnings release and this presentation.

Now we'll move to the 2016 highlights on slide 3. 2016 was another positive year for Cabot Oil & Gas, especially in light of the lower commodity price backdrop we navigated through for a significant portion of the year. Our plan for the year was to deliver returns-focused production and reserve growth, to invest capital prudently, while targeting a free cash flow positive investment program, and to continue to improve on our top tier cost structure, and to maintain strength of our balance sheet.

I'm confident to say that we executed across the board on all these goals. Cabot grew production and proved reserves by 4% and 5%, respectively, from a capital program that was over 50% lower than 2015. Despite lower realized commodity prices for the year, which resulted in Cabot's lowest realized natural gas price in its history, we were able to deliver our production and reserve growth, while generating positive free cash flow. And that is quite an accomplishment.

Our continued emphasis on cost control was demonstrated by our record low all-source finding cost of $0.37 per Mcfe, and our 11% year-over-year reduction in cash operating expense per unit. A significant portion of the reduction in our cost structure was driven by internally-sourced operating efficiency gains that will remain in place, regardless of changes in the service cost environment.

Our balance sheet remains strong, with approximately $500 million of cash on hand, and approximately $1.7 billion of available commitments on our undrawn credit facility. During the year, we reduced our debt outstanding by almost $500 million by utilizing a portion of the proceeds from our equity issuance in early 2016, resulting in a significant reduction in leverage metrics throughout the year.

On the operational front, we announced an increase in our Marcellus EUR to 4.4 Bcf per 1,000 foot a lateral, improving our peer-leading EUR in Appalachia. I plan to discuss our updated Marcellus EUR further in the call.

Now let's move to slide 4, where we have highlighted our production and reserve growth over the last few years. You can see that we have averaged a 15% and 16% compounded annual growth rate for production reserves, [respectively], over the last three years.

While our 2017 production growth guidance of 5% to 10% is slightly below our historic growth rate as we await new takeaway capacity in the Marcellus, we are forecasting our discretionary cash flow to double this year based on recent strip prices, which is driven by significant improvement in cash margins due to higher realized prices and lower operating costs. We do expect a return to growth levels above this historic CAGR in 2018, as new infrastructure is in place throughout Appalachia.

While we have not officially guided to 2019 production levels, our internal forecast shows an even more robust level of growth in 2019. On the reserve front, I would emphasize that our proved developed growth has outpaced our total reserve growth, highlighting that our growth is coming through the drill bit, and is not a function of adding excessive levels of proved undeveloped reserves.

Now I'll flip to slide 5 through 7, kind of cover those, all at one comment. They highlight the continued improvement we have seen in our drilling, completion and operating costs over the last three years. The cost reductions our operating team have achieved in both the Marcellus and Eagle Ford which are represented on slide 5, have translated into significant improvements in our finding cost, and our cash operating cost, as highlighted on slides 6 and 7, respectively.

Slide 8 illustrates our capital budget and operating program for 2017. As we highlighted in the press release this morning, we have increased our total program spending for the year from $625 million to $720 million, which includes an $85 million increase for additional Eagle Ford activity to capitalize on the higher prices, and most importantly, improved well productivity, a $20 million increase in equity pipeline investments driven by a more favorable outlook on the construction timing for Atlantic Sunrise, and a $15 million increase in the Marcellus primarily for additional drilling activity driven by faster drilling times.

These increases in capital are offset by approximately $25 million of savings from additional Marcellus drilling efficiencies. We plan to spend $610 million of drilling, completion and facility capital in 2017, of which 67% will go to the Marcellus, and 33% will go to the Eagle Ford. This will fund the drilling and completion of approximately 90 net wells. We plan to exit 2017 with 45 DUCs, of which 35 are located in the Marcellus, positioning us well for accelerating production growth in 2018 upon the in-service of new takeaway capacity.

Moving to slide 9, which contains a reconciliation of the updated capital budget to the preliminary budget we discussed on the third quarter conference call, referencing the previously-mentioned changes in the capital -- in capital for the year. I would also highlight, that despite this increase in capital spending, we are currently forecasting approximately $250 million of positive free cash flow for the year, based on recent strip prices.

Additionally, while our production growth guidance of 5% to 10% remains unchanged, our year-over-year oil growth guidance of 15% is substantially higher than the 0% oil growth contained in our original budget. This increased oil growth moves us higher in our production guidance range, and allows for more flexibility around curtailments in the Marcellus during the year, if warranted. However, based on current price expectations, we do not expect curtailments to be a concern.

Moving on to the Eagle Ford operations, slide 10. During the second half of last year, we began testing new completion designs in the Eagle Ford to determine the impact of increased proppant loading, and tighter cluster spacing, diversion technology. The wells on this slide do a great job highlighting the productivity gains we are seeing from our enhanced completions. The results from a three-well pad that was completed last year are significantly outperforming the results from an offset pad that was completed with an older completion design.

Additionally, you can see that Well 1 which was recently completed with 1,800 pounds of proppant per foot is outperforming the other two wells from the same pad that were completed with slightly less proppant. While the production history is still very limited, we are encouraged by the result, and plan to implement enhanced completions throughout our program this year.

On the left side of slide 11, we highlight the impact of our enhanced completions on our Eagle Ford returns. At today's well costs, our average 9,000-foot lateral generates a rate of return over 60% at a $50 per barrel realized price, which is about what we are realizing currently. Like all of our industry peers, we anticipate some level of cost inflation this year, and are budgeting this inflation into our well costs for the second half of the year.

You can see that even when assuming this inflationary pressure on well costs, our returns are still above 45%. Based on the improved economics and the expectation of higher oil prices later in 2017, we have increased our spending in the Eagle Ford to help pivot this asset back into growth mode, as opposed to holding pattern it has been in, in the last couple of years. Accordingly, we anticipate growing our exit oil volumes this year by 50%, as opposed to the 5% we forecasted in the original budget.

Heading over to the Marcellus, and turning to slide 12, we have plotted the average cumulative production results for our Gen 4 completions, compared to our prior type curves of 3.8 Bcf per 1,000 feet, and our new type curve of 4.4 Bcf per 1,000 feet. While our sample size is still limited, with only 21 wells based on production data we have to date, and the fact that these 21 wells were drilled in the north, south, east and west, we are very confident that these results are repeatable across the field.

While it is very well understood across the industry and investment community that Cabot's wells in northeast Pennsylvania are some of the best wells in the country, slide 13 illustrates how our EUR stacks up against other natural gas operating areas across the US. In fact, our 4.4 Bcf per 1,000 feet is double that of some of our peers, who have been touting their technical expertise on the completion front. We continue to be impressed with the improvements in well productivity we see year after year, and are in the process of testing other enhancements to our well design to further improve our economics.

Slide 14 demonstrates how our increasing EURs, our improvements in well cost, and better realized pricing are impacting [area] economics. We originally budgeted $7.9 million for our 8,000-foot lateral Gen 4 well costs back in October of last year. However, we are currently averaging about 10% lower, due to improved operating efficiencies.

Approximately 75% of our costs are locked in under current contracts, so we are anticipating only a slight increase in well cost by year end. With this anticipated well cost, our rates of return at the current Leidy strip meet or exceed any return we have seen across the industry.

Moving on to marketing and infrastructure, slide 15 shows Cabot's monthly realized natural gas prices before hedges, highlighting the significant improvement we have seen in pricing, as we entered the winter heating season. While fourth quarter pricing was greatly improved relative to the first three quarters of last year, the first quarter of 2017 has been even better, driven by a strong January and February. While the strip has pulled back as of late, due to unfavorable weather forecasts, we are still forecasting a substantial improvement in year-over-year realized prices, driven by higher NYMEX prices, tighter [basis] differentials, and a stronger portfolio of fixed price contracts, primarily for the summer season.

As the title of slide 16 indicates, 2018 will be an inflection year for Cabot, both in terms of infrastructure additions, and for our growth story. Moving to the left -- moving from the left, to the right of the slide, Orion, Moxie and Lackawanna all remain on schedule. Orion received FERC certificate on February 2, and is expected to begin construction this summer.

Our two power plant projects are currently under construction, and on track for an in-service date listed on the slide. As you're aware, Atlantic Sunrise has reached several milestones since we last spoke, receiving the FERC -- or the final environmental impact statement on December 30, 2016, and the FERC certificate approving the project on February 3.

The next steps for Atlantic Sunrise, including finishing up permit work with the Pennsylvania DEP and the US Army Corps of Engineers, and receiving the FERC notice -- and we need to receive the FERC notice to proceed with construction. We expect all final approvals to be received by mid-summer, and construction to begin shortly afterwards. And the in-service date remains mid 2018. Based on the recent progress that was made on these projects, we remain extremely confident in delivering on our production targets for 2018.

The PennEast project continues to make progress, and is expected to receive its final environmental impact statement in April, while Constitution pipeline is still awaiting an answer from the second court of appeals for permission to move forward. We expect news regarding Constitution's status later in the second quarter.

As the slide illustrates, upon in-service of all these projects, Cabot will have the ability to double production volumes from its 2016 exit rate. As we have communicated in the past, the pace at which we fill this capacity with incremental growth volumes will ultimately be dependent upon the market environment. I would also highlight that our marketing team continues to identify new opportunities to increase Cabot's growth trajectory out of the Marcellus, as evidenced through addition of a new three-year sales contract of $150 million per day on Atlantic Sunrise that was announced at the end of last year.

Now we'll move on to slide 17, which highlights the anticipated improvement in our realized pricing, upon completion of the previously mentioned projects. We expect our overall realizations to improve for two primary reasons. First, the volumes that are shipped on these new projects are expected to receive favorable pricing in the new markets that we are accessing.

Second, we anticipate our volumes that remain in the local market will see an improvement in realized prices, as a result of tightening of in-basin differentials from the addition of new large scale projects like Atlantic Sunrise and Penn East, and an increase in local demand from the addition of numerous new power plants in the northeast operating area. Local demand could increase in excess of over 1 Bcf per day, beginning as early as January 2019 from power plant generation alone.

I would also like to highlight that while our forecasted differentials improved significantly between 2017 and 2018, without adding material amounts of transportation expense, our differentials are expected to improve even further in 2019, as we will receive the full-year impact of the projects that were placed in service intermittently throughout 2018. Not to mention, if Constitution is placed in service in 2018 or early 2019, that will have an even further positive impact on pricing, as those volumes will reach favorable markets in the northeast.

On another takeaway from this slide, that I would like to add is that for 2017, 36% of our volumes are locked in under fixed price contracts, at a weighted average price of $2.29 per Mcf, which implies a rate of return greater than 150% for our typical Marcellus well. These volumes would typically be exposed to the local northeast Pennsylvania indices that averaged about $1.30 in 2016, so we are very pleased with this portfolio fixed price contract.

Finally, on slide 18, we have attempted to address the most commonly asked question to get -- we get from our shareholders. And that is, what are you going to do with all the free cash flow you expect to generate? I would first highlight, that this is certainly a high-class problem to have, and most companies would be envious of our position. We have said time and time again, that we believe we can ultimately generate the most shareholder value by delivering a returns-focused production and reserve growth, and our current organic five-year plan delivers on this strategy.

With that being said, we will continue to evaluate new opportunities, both internal and external, to identify new platforms for future growth that compete for capital internally, and provide competitive full-cycle economics. Additionally, we plan to continue to evaluate returning incremental cash to the shareholder, most likely through increased dividend, and potentially reduce our debt levels over time, as maturities come due.

With the organic growth program we have teed up, you can rest assured, that we will remain as disciplined with our capital as our track record has demonstrated, and only look to invest capital, if we believe it will create long-term value for our shareholders. So with that, Anita, we will go ahead, and open the call up for questions.

(Operator Instructions)

Our first question comes from Holly Stewart with Scotia Howard. Please go ahead.

Good morning, gentlemen.

Hello, Holly.

Maybe Dan, just picking up where you left off, on the uses of free cash. I see one of the things on the slide deck says, including new outlets for growth in the Marcellus. Can you just maybe give us a little color there? Is that new projects, or more power plant deals, or more acreage, just kind of some thoughts there?

Well, Holly, it's on a, just a broad comment, and I'll back up to my thoughts of full-cycle returns. So all of those that we mentioned, whether it's -- not new acreage, but it looks like that we can facilitate our longer laterals, or some of the offset acreage, which would not expand very far from our core assets. And that's just because of the results we see in our core, we would entertain an idea looking at that type of opportunity.

I don't put much weight on the capture of that opportunity, simply because there's not a great deal of acreage that would fit our model. In looking at other growth areas though, and I can flip it to Jeff, but we do continue to look for the opportunities to expand our growth profile, through arrangements that would allow either additional firm in places or in basin projects to remove some of the gas from the basin, and get to a different price points. Jeff, do you want to?

Sure. Holly, in addition to that, we have a very active program, in and around our gathering system in Susquehanna county for more additional on, what we call on-system sales. So we've picked up some small loads that have to do with compressed natural gas. We're looking at some small methanol facilities and some other demand projects, in and around our gathering system, that typically would not include interstate pipeline commitments. On top of that, we still think we have an opportunity with PennEast volumes, maybe growing our presence on that pipeline, so lots of things going on.

Okay. Great. And maybe, Jeff, as a follow on to that, I was just trying to understand slide 18. You've got a lot of these fixed price sales agreements. I'm assuming those are short term. Can that work into that 2018 column?

Absolutely. We expect to continue our fixed price program, really as opportunity permits. Those volumes have to do with a program for the winter of 2016, 2017, and also summer of 2017.

Okay. Great. And then, maybe just one quick followup. Slide 14 shows the drilling and completion costs where you've essentially locked in the majority of your program for 2017. How does 2018 look at this point?

I'm sorry. I was not -- can you repeat it, please, Holly? I'm sorry.

Just on the slide that shows your locked in costs, I think it's slide 14, that says 73% of drilling, 78% of completion costs are locked in. Just wondering how 2018 was looking so far?

Well, 2018, we have not locked in costs in 2018. It's certainly our plan to discuss the win-win arrangement we can find with the service providers to lock in costs at the appropriate time.

Got it. Thanks, gentlemen.

Thank you.

Our next question comes from Pearce Hammond with Simmons. Please go ahead.

Good morning, and congrats on a great 2016. My first question is on slide 17, it's very helpful. You give the illustrated differential. Should we think of that as guidance, or kind of soft guidance for 2017 and 2018, that the $0.75 and $0.50?

Yes. We have, both with Jeff and Matt, have both looked at our anticipated forecast, and provided our best guess on a weighted average basis, and that's exactly what that slide illustrates.

Great. And then, congrats on the success with the Gen 4 completions. Do you feel like you're getting towards the end of the -- end of the line on improvements, or do we see continued improvements, and could we see like a Gen 5? And then furthermore, on the Gen 4, if you could, could you be a bit more specific about some of the things that you're doing, either on the specific sand loadings, or stage spacing, et cetera?

Okay. First, just a macro comment, Pearce. The question about efficiency gains, I think, is an industry question. You can ask all operators, with the improvements that you see in every IR deck of efficiency gains, whether it's loading, whether it's cluster spacing, whether it's diversion technology, all of those different combinations are being tried throughout industry, and you've seen significant improvements. And we continue to see those improvements also.

Some areas are more conducive to a response from those improvements than others, but we do think that with our continued tweaking, and the ideas that we have pilots ongoing right now, with another -- whether it morphs into a Gen 5, Gen 6, Gen 7, we will come out with the results, if we show positive impact. But I think the entire industry is continuing to find ways through technology, to extract more oil and gas out of the ground, and we're no exception.

Great. And then, my last one, Dan, is on slide 14, you do a good job of outlining the percent of drilling costs and the completion costs in the Marcellus that are fixed or locked in for 2017. Have you done the same sort of thing in the Eagle Ford?

Well, we only have a small percentage of our costs, or the oil hedged right now, but we do have -- we do have some costs that are locked in on the Eagle Ford. Steve, why don't you explain? Steve Lindeman, can go over what we've done in the Eagle Ford.

So, Pearce, we've got the drilling contract committed for this year and -- excuse me -- our completion costs for the first half of this year. And that's why we're modeling a little bit of a step-up in cost for the second half of the year.

Great. Thank you very much.

Thanks, Pearce.

Our next question is from Brian Singer with Goldman Sachs. Please go ahead.

Thank you. Good morning.

Hey, Brian.

In the Eagle Ford, is the increase in activity here, simply a drawdown of inventory at a faster rate, or is there a more meaningful change in the inventory? I know you highlighted some of the better economics as well, but is there any shift in inventory, or any other, more exploratory measures here, you're taking place on the Eagle Ford?

Well, I'll make a comment, and then I'll turn it to Steve again. But in looking at the Eagle Ford, we along with again, the industry as a whole and the Permian operators have -- where the majority of the activity is, have illustrated how much can be done in the oil windows, to improve recoveries and efficiencies. And just the tweaking that we've done, and we're early stage on what we think we might be able to try to do in the Eagle Ford.

But we did see significant increase that we felt warranted, with the increase, we felt it warranted the additional capital, and to grow that liquids volume, as we have now planned on with our 2017 program. So we're very pleased with what we've seen on, what we've been able to get out of that Eagle Ford right now. Steve?

Yes. So, Brian, like you mentioned, part of it is our increased well performance with the next generation of completion, and then obviously, we've spent a significant time last year, really working to drive both our capital costs and our operating costs down. As far as the gross inventory, that remains the same, but obviously, we continue to look at offset opportunities we'd love to try, and bolt on to our acreage, if the opportunity arises.

Steve, you might make a comment of what we have done, and some of the savings that we're seeing now that will remain with us, in the on the location and [water]?

So let me start on the drilling side. About 60% of the decrease in our costs related to -- let's go back to 2014, are items that will -- that should stick with us. We're drilling longer laterals.

Yesterday, we just -- or two days ago just drilled 4,000 foot in the lateral section on a well, so we're really working to improve our penetration rate. On the operating cost side, in 2016 we worked quite a bit on electrification, and right now we have over 90% of our wells on either micro grid or predominantly on utility power, which is a significant LOE reduction.

And then we're just seeing benefits -- we are working with another partner to lay some salt water disposal lines in the southern part of the field, and we're seeing some significant benefits in reduced salt water disposal costs on those properties.

Great. Thank you. And then shifting to the Marcellus, just wanted to confirm, does the new EUR apply to the average, or the entirety of the remaining Marcellus inventory? Or are there any regional or other limitations, and does your assumption for that well spacing stay the same?

Well spacing stays the same, Brian, and back to my comment, that the sample pool we have are, is drawn from well locations that are on the far east side of our field, far west side of our field, and the north and south. So we do think that the application of our Gen 4 EUR per 1,000 is appropriate for the field.

Great. Thank you.

Thank you.

Our next question comes from Anthony Diaz with Raymond James. Please go ahead.

Hi, guys. Thanks for taking my question. I was hoping you guys could help me out, and you guys talked about the translation to the 4.4 Bcf per 1,000 foot lateral on the Lower Marcellus.

I was wondering if you guys could talk me through, kind of how should we think about that for the Upper Marcellus, if it's the same translation? And then, just kind of on what the well mix is on say, a 10-well pad between the Upper and Lower Marcellus as it stands today?

Well, right now, we are effecting our completions in the Lower Marcellus. We have a number of wells, and a number of portions of wells that have been completed in the Upper Marcellus. And the portions of wells would be in curve, and or as we lay out our lateral in the lower portion, we purposely have designed wells that would allow us to continue to gather data in the Upper Marcellus.

But as far as our full development program, we are concentrated as any prudent operator would, concentrated in the Lower Marcellus at this point in time. And then, we'll work up into the Upper Marcellus at an appropriate time later.

Okay. Yes. Thanks for the clarity there. And then, last question, kind of goes to the question before me.

How should we be viewing -- what is the read-through of sending more capital to Eagle Ford, as opposed to reallocating that into the Marcellus? I mean, the returns that we're seeing in Marcellus seem to really blow those out of the water in the Eagle Ford. Is this a function of kind of outlook on the macro environment, kind of holding this off until more pipe comes on, or is this a commodity hedge? How are you guys thinking about it?

Yes. The macro environment is dictating today, what we can do with the Marcellus. We have been in a -- kind of what, I'd call a holding pattern, even though we're generating decent growth. And we can -- with the less than $400 million, we can generate growth in both production and reserves, and still generate free cash.

But in a situation that would have new infrastructure, and allow us to grow -- keep in mind, that our capital intensity necessary to grow those volumes into our anticipated infrastructure build-out, is not that capital intensive, and doesn't take a great deal of capital to be able to drill the number of wells, complete the number of zones that we need, to increase our production an additional Bcf a day, rather unique in the industry to be able to say that.

But the production volumes, and our forecast generate so much free cash, that there's not that opportunity to -- because of the low capital intensity, there's not the opportunity to redeploy it all into the Marcellus. I can assure you, every Mcf that we can put in a pipeline up in the Marcellus, we're going to do that, and we'll have ample funds to be able to fulfill that objective.

But when we look at our cost of capital of less than 8%, and you look at a 60% return, we think right now with having a $0.5 billion on our balance sheet in cash, and a $1.7 billion available on our undrawn credit facility, we felt like investing those funds for a 60% return made sense.

All right. Thanks, guys. I appreciate the color.

Okay, thank you.

Our next question comes from David Deckelbaum with KeyBanc, please go ahead.

Good morning, Dan and Scott, and everyone.

Hi, David

Thank you. I just wanted to follow up. I know a lot of people have asked questions about the allocation between Eagle Ford and Marcellus. Just kind of curious, what led to the decision, that one, a one-rig type program was correct for this year in the Eagle Ford, given the free cash?

Is it sort of a wait and see, with more of the enhanced completions, and then based on successes, we could see further activity there? Because you also mentioned that you're looking at potential bolt-ons and inventory expansion, as opposed to perhaps re-growing this asset towards monetizing at some point. Just trying to get the thought process around, why one rig was kind of the right step for this year there?

Well, a couple things. One, when we put together our initial budget in October of 2016, it was not as pleasant of an environment on the gas side or the oil side, and our values used on commodity pricing dictated, with our methodology of putting together a program within cash flow, we felt like that we would -- we would only have a minimal amount of activity in the Eagle Ford.

As you continue to see a little bit of price improvement, both on the oil side and the gas side, we felt that the -- and with having a little bit more time on the completions that we've talked about, the enhancements to the completions that we've talked about, we've had a little bit more curve fit on the efficiency gains in that regard. And so, from October to February, we decided that it was prudent, and we felt comfortable with the commodity price where we are, that we would allocate the funds to the Eagle Ford.

I appreciate that, Dan. And Jeff, just a question for you, on the fixed price contracts. The -- I know you talked about these are sort of short term, they would address winter and summer seasonality. Can you give me sort of an idea of how much that component becomes, in terms of percentage of gas sold, and sort of your summer months, versus sort of the average of the 30%-some for the year?

Well, I think the summer is predominantly the larger percentage, but the April, October piece is what we're considering the summer, so maybe 40%, 45%.

Okay. That's helpful. All right, that's it from me, guys. Thank you.

Thank you.

This concludes our question and answer session. I would like to turn the conference back over to Dan Dinges for any closing remarks. Please go ahead.

Thank you, Anita. I appreciate the interest from all of our either new shareholders, or long-term shareholders. As I previously mentioned, this is an inflection point for Cabot. We continue to generate the free cash flow. At the same time, we have a very clear path to doubling our production in the next few years. So all this is good, and I look forward to our next opportunity to visit. Thank you.

The conference has now concluded. Thank you for attending today's presentation. You may now disconnect.